Edgar Filing: CROSS BORDER RESOURCES, INC.

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

☒

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2014

☐

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ______________to ______________

Commission File Number 000-52738

CROSS BORDER RESOURCES, INC.

(Exact Name of Registrant as Specified in Its Charter)

Nevada	98-0555508
(State or Other Jurisdiction of Incorporation or Organization)	(I.R.S. Employer Identification No.)

2515 McKinney Avenue, Suite 900 Dallas, TX	75201
(Address of Principal Executive Offices)	(Zip Code)

(210) 226-6700

(Registrant’s Telephone Number, Including Area Code)

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act:

Common Stock, par value $.001

(Title of class)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
☐ Yes ☒ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

☐ Yes ☒ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ☐	Accelerated filer ☐
Non-accelerated filer☐ (Do not check if a smaller reporting company)	Smaller reporting company ☒

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

☐ Yes ☒ No

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:

As of May 15, 2015, the Registrant had 17,336,226 shares of common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

None.

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION


Item 1.	Financial Statements	3
	Balance Sheets as of September 30, 2014 (unaudited) and December 31, 2013	3
	Unaudited Statements of Operations for the Three and Nine Months Ended September 30, 2014 and September 30, 2013	5
	Unaudited Statements of Cash Flows for the Nine Months Ended September 30, 2014 and September 30, 2013	7
	Unaudited Notes to Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	18
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	25
Item 4.	Controls and Procedures	25

PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	27
Item 1A.	Risk Factors	27
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	27
Item 3.	Defaults Upon Senior Securities	27
Item 4.	Mine Safety Disclosures	27
Item 5.	Other Information	27
Item 6.	Exhibits	29

PART I. FINANCIAL INFORMATION

Item 1.

Financial Statements

Cross Border Resources, Inc.

Balance Sheets

	September 30,			December 31,
	2014			2013
	(unaudited)
ASSETS

Current Assets
Cash and Cash Equivalents	$	425,565		$	726,239
Accounts Receivable – Oil and Natural Gas Sales		1,632,398			2,086,239
Accounts Receivable – Related Party		1,558,772			24,630
Derivative Asset		12,028			—
Prepaid Expenses & Other Current Assets		75,436			87,443
Assets Held for Sale		14,951,977			—
Deferred Tax Asset		19,600			19,600
Total Current Assets		18,675,776			2,944,151

Oil and Gas Properties		26,352,612			56,561,040
Less: Accumulated Depletion, Amortization, and Impairment		(11,850,634	)		(20,941,867	)
Net Oil and Gas Properties		14,501,978			35,619,173

Other Assets
Other Property and Equipment, net of Accumulated Depreciation of $110,278 and $95,828 in 2014 and 2013, respectively		20,192			34,641
Restricted Cash		233,949			206,087
Deferred financing costs		58,444			91,242
Other Assets		54,324			54,324
Total Other Assets		366,909			386,294

TOTAL ASSETS	$	33,544,663		$	38,949,618

The accompanying notes are an integral part of these financial statements.

	September 30,			December 31,
	2014			2013
	(unaudited)
LIABILITIES AND STOCKHOLDERS’ EQUITY

Current Liabilities
Accounts Payable - Trade	$	1,725,483		$	1,268,257
Accrued Expenses & Other Payables		291,129			63,101
Derivative Liability		—			38,109
Environmental Liability – Current Portion		2,057,175			1,400,000
Liabilities associated with ARO on Assets Held for Sale		1,576,522			—
Line of Credit		9,200,000			—
Deferred Tax Liability		19,600			19,600
Total Current Liabilities		14,869,909			2,789,067

Non-Current Liabilities
Asset Retirement Obligations		1,576,521			3,514,898
Environmental Liability, Net of Current Portion		—			687,973
Line of Credit		—			12,200,000
Litigation Settlement Payable		600,000			—
Total Non-Current Liabilities		2,176,521			16,402,871
Total Liabilities		17,046,430			19,191,938

Commitments & Contingencies (Note 9)

Stockholders’ Equity
Common Stock ($0.001 par value; 99,000,000 shares authorized and 17,336,226 issued and outstanding as of September 30, 2014 and as of December 31, 2013)		17,336			17,336
Additional Paid in Capital		33,462,473			33,462,473
Accumulated Deficit		(16,981,576	)		(13,722,129	)
Total Stockholders’ Equity		16,498,233			19,757,680

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	33,544,663		$	38,949,618

The accompanying notes are an integral part of these financial statements.

Cross Border Resources, Inc.

Statements of Operations

	Three Months Ended September 30,
	2014			2013
	(unaudited)			(unaudited)
Revenues
Oil and gas sales	$	2,961,729		$	3,430,100

Expenses:
Operating costs		594,847			532,443
Natural gas marketing and transportation expenses		12,541			16,750
Production taxes		249,273			388,546
Depreciation, depletion, amortization, and Impairment		6,943,555			1,082,315
Accretion expense		17,650			37,982
General and administrative		203,866			251,551
Total expense		8,021,732			2,309,587

Income (loss) from operations		(5,060,003	)		1,120,513

Other income (expense):
Gain (loss) on derivatives		88,068			(304,858	)
Loss on settlement of litigation		(900,000	)		—
Interest expense		(107,632	)		(142,122	)
Miscellaneous other income (expense)		—			—
Total other income (expense)		(919,564	)		(446,980	)

Income (loss) before income taxes		(5,979,567	)		673,533

Current tax benefit		(—	)		(—	)
Deferred tax expense		—			—
Income tax expense		—			—
Net income (loss)	$	(5,979,567	)	$	673,533

Net income (loss) per share:
Basic		(0.37	)		0.04
Fully diluted	$	(0.30	)	$	0.03
Weighted average shares outstanding:
Basic		17,336,226			17,336,226
Fully diluted		21,023,726			21,023,726

The accompanying notes are an integral part of these financial statements.

Cross Border Resources, Inc.

Statements of Operations

	Nine Months Ended September 30,
	2014			2013
	(unaudited)			(unaudited)
Revenues
Oil and gas sales	$	10,149,406		$	10,224,147

Expenses:
Operating costs		1,542,932			1,865,199
Natural gas marketing and transportation expenses		84,859			65,890
Production taxes		825,297			783,141
Depreciation, depletion, amortization, and Impairment		8,823,851			3,876,954
Accretion expense		168,735			109,684
General and administrative		637,522			847,677
Total expense		12,083,196			7,548,545

Income (loss) from operations		(1,933,790	)		2,675,602

Other income (expense):
Gain (loss) on derivatives		(45,153	)		(327,415	)
Gain (loss) on settlement of debt		—			858,452
Loss on settlement of litigation		(900,000	)		—
Interest expense		(380,507	)		(488,144	)
Total other income (expense)		(1,325,660	)		42,893

Income (loss) before income taxes		(3,259,450	)		2,718,495

Current tax benefit		(—	)		(—	)
Deferred tax expense		—			—
Income tax expense		—			—
Net income (loss)	$	(3,259,450	)	$	2,718,495

Net income (loss) per share:
Basic		(0.21	)		0.16
Fully diluted	$	(0.18	)	$	0.13
Weighted average shares outstanding:
Basic		17,336,226			17,112,700
Fully diluted		21,023,726			20,800,200

The accompanying notes are an integral part of these financial statements.

Cross Border Resources, Inc.

Statements of Cash Flows

	Nine Months Ended September 30,
	2014			2013
	(unaudited)			(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(3,259,450	)	$	2,718,495
Adjustments to reconcile net income (loss) to cash used by operating activities:
Depreciation, depletion, amortization, and impairment		8,823,851			3,876,954
Gain on settlement of creditors liability		—			(350,800	)
Gain on conversion of notes payable		—			(485,416	)
Settlement of environmental liability		(20,798	)		(13,167	)
Accretion of asset retirement obligations		168,735			109,684
Amortization of deferred financing costs		32,798			(1,130	)
Change in derivative instruments		(50,137	)		383,180
Changes in operating assets and liabilities:
Accounts receivable		622,102			140,051
Accounts receivable – related party		(1,534,142	)		—
Prepaid expenses and other current assets		(184,112	)		369,380
Accounts payable		457,226			(781,646	)
Restricted cash		—			(206,087	)
Accrued expenses		218,026			142,738
Litigation payable		600,000			—
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		5,874,099			5,902,236

CASH FLOWS USED IN INVESTING ACTIVITIES
Capital expenditures - oil and gas properties		(3,174,773	)		(7,954,272	)
NET CASH USED IN INVESTING ACTIVITIES		(3,174,773	)		(7,954,272	)

CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings on line of credit		—			12,200,000
Reduction of principal on line of credit		(3,000,000	)		—
Payments on line of credit		(—	)		(8,750,000	)
Repayments to creditors		(—	)		(660,911	)
NET CASH (USED) PROVIDED BY FINANCING ACTIVITIES		(3,000,000	)		2,789,089

NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS		(300,674	)		737,053
Cash and cash equivalents, beginning of period		726,239			241,561
Cash and cash equivalents, end of period	$	425,565		$	978,614

Supplemental disclosures of cash flow information:
Interest paid	$	347,708		$	398,040

NON-CASH TRANSACTIONS
Revisions of ARO	$	(554,383	)	$	—
Issuance of common stock to settle liability	$	—			(692,967	)
Additions of ARO	$	22,191		$	26,740

The accompanying notes are an integral part of these financial statements.

Cross Border Resources, Inc.

Unaudited Notes to Financial Statements

1. Organization

Nature of Operations

The Company is an independent natural gas and oil company engaged in the exploration, development, exploitation, and acquisition of natural gas and oil reserves in North America. The Company’s area of focus is the State of New Mexico, particularly southeastern New Mexico. The Company has two wholly-owned subsidiaries, which are inactive: Doral West Corporation and Pure Energy Operating, Inc, and accordingly are not consolidated in these financial statements.

2. Going Concern

At September 30, 2014, the Company had working capital of $3,805,867 (including Assets Held for Sale of $14,951,977) and outstanding debt of $9,200,000 (consisting of a line of credit). The company would have a working capital deficit of $9,569,588 (excluding Assets Held for Sale, Net of ARO Liabilities associated with the Assets Held for Sell). The Company was not in compliance with the covenants of its line of credit with Independent Bank and had no availability under this line of credit. The Company currently does not have sufficient funds to repay these obligations. The Company is exploring available financing options, including the sale of debt, equity, or assets. If the Company is unable to finance its operations on acceptable terms or at all, its business, financial condition and results of operations may be materially and adversely affected. As a result of these conditions, there is substantial doubt regarding the Company’s ability to continue as a going concern. The accompanying financial statements do not include any adjustments to reflect the possible future effects on the recoverability and classification of assets or the amounts and classifications of liabilities that may result from the possible inability of the Company to continue as a going concern.

3. Summary of Significant Accounting Policies

In the opinion of management, the accompanying unaudited financial statements include all adjustments, consisting of only normal recurring accruals, necessary for a fair statement of consolidated financial position, results of operations, and cash flows. The information included in this Quarterly Report on Form 10-Q should be read in conjunction with the financial statements and the accompanying notes included in our Annual Report on Form 10-K for the year ended December 31, 2013 filed with the SEC on April 15, 2014. The accounting policies are described in the “Notes to Financial Statements” in the 2013 Annual Report on Form 10-K and updated, as necessary, in this Form 10-Q. The year-end balance sheet data presented for comparative purposes was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States (U.S. GAAP). The results of operations for the three and nine months ended September 30, 2014 are not necessarily indicative of the operating results for the full year or for any other subsequent interim period.

Reclassification

Certain amounts have been reclassified to conform with the current period presentation. The amounts reclassified did not have an effect on the Company’s results of operations or stockholders’ equity.

Cash and cash equivalents

The Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. At times, the amount of cash and cash equivalents on deposit in financial institutions exceeds federally insured limits. The Company monitors the soundness of the financial institutions and believes the Company’s risk is negligible.

Financial instruments

The carrying amounts of financial instruments, including cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities and long-term debt, approximate fair value as of September 30, 2014 and December 31, 2013.

Oil and natural gas properties

The Company follows the successful efforts method of accounting for its oil and natural gas producing activities. Costs to acquire mineral interests in oil and natural gas properties and to drill and equip development wells and related asset retirement costs are capitalized. Costs to drill exploratory wells are capitalized pending determination of whether the wells have proved reserves. If the Company determines that the wells do not have proved reserves, the costs are charged to expense. There were no exploratory wells capitalized pending determination of whether the wells have proved reserves at September 30, 2014 or December 31, 2013. Geological and geophysical costs, including seismic studies and costs of carrying and retaining unproved properties, are charged to expense as incurred. The Company capitalizes interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use. Through September 30, 2014, the Company had capitalized no interest costs because its exploration and development projects generally lasted less than six months. Costs incurred to maintain wells and related equipment are charged to expense as incurred.

On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depreciation, depletion and amortization are eliminated from the property accounts, and the resulting gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depreciation, depletion and amortization, with a resulting gain or loss recognized in income.

Capitalized amounts attributable to proved oil and natural gas properties are depleted by the unit-of-production method over proved reserves using the unit conversion ratio of six Mcf of gas to one barrel of oil equivalent (“Boe”). The ratio of six Mcf of natural gas to one Boe is based upon energy equivalency, rather than price equivalency. Given current price differentials, the price for a Boe for natural gas differs significantly from the price for a barrel of oil.

It is common for operators of oil and natural gas properties to request that joint interest owners pay for large expenditures, typically for drilling new wells, in advance of the work commencing. This right to call for cash advances is typically found in the operating agreement that joint interest owners in a property adopt. The Company records these advance payments in prepaid and other current assets and release this account when the actual expenditure is later billed to it by the operator.

On the sale of an entire interest in an unproved property for cash or cash equivalents, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.

Impairment of long-lived assets

The Company evaluates its long-lived assets for potential impairment in their carrying values whenever events or changes in circumstances indicate such impairment may have occurred. Oil and natural gas properties are evaluated for potential impairment by field. Other properties are evaluated for impairment on a specific asset basis or in groups of similar assets, as applicable. An impairment on proved properties is recognized when the estimated undiscounted future net cash flows of an asset are less than its carrying value. If an impairment occurs, the carrying value of the impaired asset is reduced to its estimated fair value, which is generally estimated using a discounted cash flow approach. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized.

Unproved oil and natural gas properties do not have producing properties. As reserves are proved through the successful completion of exploratory wells, the cost is transferred to proved properties. The cost of the remaining unproved basis is periodically evaluated by management to assess whether the value of a property has diminished. To do this assessment, management considers estimated potential reserves and future net revenues from an independent expert, the Company’s history in exploring the area, the Company’s future drilling plans per its capital drilling program prepared by the Company’s reservoir engineers and operations management and other factors associated with the area. Impairment is taken on the unproved property cost if it is determined that the costs are not likely to be recoverable. The valuation is subjective and requires management to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual results.

For the three and nine months ended September 30, 2014, the Company recorded an impairment charge of $6,500,000 against our oil and gas properties.

Revenue and accounts receivable

The Company recognizes revenue for its production when the quantities are delivered to, or collected by, the purchaser. Prices for such production are generally defined in sales contracts and are readily determinable based on certain publicly available indices. All transportation costs are included in lease operating expense.

Accounts receivable—oil and natural gas sales consist of uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 to 60 days of production. Accounts receivable—other consist of amounts owed from interest owners of the Company’s operated wells. No interest is charged on past-due balances. Payments made on all accounts receivable are applied to the earliest unpaid items. The Company reviews accounts receivable periodically and reduces the carrying amount by a valuation allowance that reflects its best estimate of the amount that may not be collectible. There was no reserve for bad debts as of September 30, 2014 or December 31, 2013.

Other property

Furniture, fixtures and equipment are carried at cost. Depreciation of furniture, fixtures and equipment is provided using the straight-line method over estimated useful lives ranging from three to ten years. Gain or loss on retirement or sale or other disposition of assets is included in income in the period of disposition.

Income taxes

The Company is subject to U.S. federal income taxes along with state income taxes in New Mexico. When tax returns are filed, it is highly certain that some positions taken would be sustained upon examination by the taxing authorities, while others are subject to uncertainty about the merits of the position taken or the amount of the position that would be ultimately sustained. The benefit of a tax position is recognized in the financial statements in the period during which, based on all available evidence, management believes it is more likely than not that the position will be sustained upon examination, including the resolution of appeals or litigation processes, if any. Tax positions taken are not offset or aggregated with other positions. Tax positions that meet the more-likely-than-not recognition threshold are measured as the largest amount of tax benefit that is more than 50% likely of being realized upon settlement with the applicable taxing authority. The portion of the benefits associated with tax positions taken that exceeds the amount measured as described above is reflected as a liability for unrecognized tax benefits in the accompanying balance sheet along with any associated interest and penalties that would be payable to the taxing authorities upon examination. Interest and penalties associated with unrecognized tax benefits are classified as additional income taxes in the Company’s Statements of Operations. The Company accrues interest and penalties, if any, related to unrecognized tax benefits as a component of income tax expense.

Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the year of the enacted tax rate change. In addition, a valuation allowance is established to reduce any deferred tax asset for which it is determined that it is more likely than not that some portion of the deferred tax asset will not be realized.

Asset retirement obligations

Asset retirement obligations (“AROs”) associated with the retirement of tangible long-lived assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets in the period incurred. The cost of the tangible asset, including the asset retirement cost, is depreciated over the useful life of the asset. AROs are recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligations discounted at the Company’s credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. If estimated future costs of AROs change, an adjustment is recorded to both the ARO and the long-lived asset. Revisions to estimated AROs can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment.

Earnings per common share

The Company reports basic earnings per common share, which excludes the effect of potentially dilutive securities, and diluted earnings per common share, which includes the effect of all potentially dilutive securities, unless their impact is anti-dilutive.

Recently issued accounting pronouncements

In April 2014, the FASB issued Accounting Standards Update (“ASU”) 2014-08, Reporting Discontinued Operations and Disclosures of Components of an Entity(“ASU 2014-08”). ASU 2014-08 revises the definition of discontinued operations by limiting discontinued operations reporting to disposals of components of an entity that represent strategic shifts that have (or will have) a major effect on an entity’s operations and financial results, removing the lack of continuing involvement criteria and requiring discontinued operations reporting for the disposal of an equity method investment that meets the definition of discontinued operations. The update also requires expanded disclosures for discontinued operations, including disclosure of pretax profit or loss of an individually significant component of an entity that does not qualify for discontinued operations reporting. The update is effective prospectively to all periods beginning after December 15, 2014. Currently, the Company does not expect the adoption of ASU 2014-08 to have a material impact on our financial statements or results of operations.

Effective January 1, 2016, the Company will be required to adopt the amended guidance of Accounting Standards Codification (ASC) Topic 718, Compensation - Stock Compensation, which seeks to resolve the diversity in practice that exists when accounting for share-based payments. The amended guidance requires a performance target that affects vesting and that could be achieved after the requisite service period to be treated as a performance condition. The Company will be required to adopt the amended guidance either prospectively to all awards granted or modified after the effective date or retrospectively to all awards with performance targets that are outstanding as of the beginning of the earliest annual period presented in the consolidated financial statements and to all new or modified awards thereafter. The Company does not expect the adoption of this amended guidance to impact financial results.

Effective January 1, 2016, the Company will be required to adopt the amended guidance of ASC Topic 810, Consolidation (Topic 810), which seeks to improve targeted areas of the consolidation guidance for legal entities such as limited partnerships, limited liability corporations, and securitization structures. The amended guidance changes the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. The changes include, among others, modification of the evaluation whether limited partnerships and similar legal entities are variable interest entities or voting interest entities and elimination of the presumption that a general partner should consolidate a limited partnership. The Company will be required to adopt Topic 810 either on a full retrospective basis to each prior reporting period presented or on a modified retrospective basis with the cumulative effect of initially applying the new guidance recognized at the date of initial application. The Company has not yet completed its assessment of the impact of the amended guidance on its financial statements but does not expect the adoption of this amended guidance to have a significant impact on financial results.

Effective January 1, 2017, the Company will be required to adopt the new guidance of ASC Topic 606, Revenue from Contracts with Customers (Topic 606), which will supersede the revenue recognition requirements in ASC Topic 605, Revenue Recognition. Topic 606 requires the Company to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new guidance requires the Company to apply the following steps: (1) identify the contract with a customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract; and (5) recognize revenue when, or as, the Company satisfies a performance obligation. The Company will be required to adopt Topic 606 either on a full retrospective basis to each prior reporting period presented or on a modified retrospective basis with the cumulative effect of initially applying the new guidance recognized at the date of initial application. If the Company elects the modified retrospective approach, it will be required to provide additional disclosures of the amount by which each financial statement line item is affected in the current reporting period, as compared to the guidance that was in effect before the change, and an explanation of the reasons for significant changes. The Company has not yet completed its assessment of the impact of the new guidance on its consolidated financial statements. On April 29, 2015, the Financial Accounting Standards Board issued a proposed Accounting Standards Update (FASB) to defer the effective date of Topic 606 to annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. If the FASB proceeds with the deferral of the effective date as proposed, this will mean the Company will be required to adopt the new guidance of ASC 606 effective January 1, 2018.

In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“ASU 2014-15”), an amendment to FASB Accounting Standards Codification (“ASC”) Topic 205, Presentation of Financial Statements. This update provides guidance on management’s responsibility in evaluating whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. This ASU 2014-15 is effective for annual periods ending after December 15, 2016, and for annual and interim periods thereafter. Early adoption is permitted. The Company does not expect the adoption of ASU 2014-15 to have a material impact on our consolidated financial statements or results of operations. If events occur in future periods that could affect our ability to continue as a going concern, we will provide the disclosures required by ASU 2014-15.

The Company has reviewed other recently issued, but not yet adopted, accounting standards in order to determine their effects, if any, on our results of operations, financial position and cash flows. Based on that review, we believe that none of these recent pronouncements will have a significant effect on our current or future earnings or operations.

4. Asset retirement obligations

The following is a description of the changes to the Company’s asset retirement obligations for the periods ended September 30, 2014 and December 31, 2013:

	September 30,			December 31,
	2014			2013

Asset retirement obligations at beginning of year	$	3,514,898		$	3,317,358
Loss on Settlement		(926	)		—
Settlement of liabilities		(3,314	)		(1,284	)
Revision of previous estimates		(554,287	)		—
Accretion expense		168,735			148,364
Additions		27,107			51,460
Asset retirement obligations at end of period	$	3,153,043		$	3,514,898
ARO Classified as Liabilities Held for Sale		(1,576,522	)		—
Asset Retirement Obligation, Non-Current	$	1,576,521		$	3,514,898

5. Property and equipment

Oil and natural gas properties

The following table sets forth the capitalized costs under the successful efforts method for oil and natural gas properties:

	September 30,			December 31,
	2014			2013

Oil and natural gas properties	$	26,352,612		$	56,561,040
Less accumulated depletion and impairment		(11,850,634	)		(20,941,867	)
Net oil and natural gas properties capitalized costs	$	14,501,978		$	35,619,173

Capitalized costs related to proved oil and natural gas properties, including wells and related equipment and facilities, are evaluated for impairment based on the Company’s analysis of undiscounted future net cash flows. If undiscounted future net cash flows are insufficient to recover the net capitalized costs related to proved properties, then the Company recognizes an impairment charge in income equal to the difference between carrying value and the estimated fair value of the properties. Estimated fair values are determined using discounted cash flow models. The discounted cash flow models include management’s estimates of future oil and natural gas production, operating and development costs, and discount rates.

Uncertainties affect the recoverability of these costs as the recovery of the costs outlined above are dependent upon the Company obtaining and maintaining leases and achieving commercial production or sale.

During the three and nine months ended September 30, 2014, the Company recorded a $6.5 million impairment charge against its oil and gas assets. Additionally, the Company reclassified half of its oil and gas assets to assets held for sale (see Note 12).

Other property and equipment

The historical cost of other property and equipment, presented on a gross basis with accumulated depreciation is summarized as follows:

	September 30,			December 31,
	2014			2013

Other property and equipment	$	130,470		$	130,469
Less accumulated depreciation		(110,278	)		(95,828	)
Net property and equipment	$	20,192		$	34,641

6. Stockholders’ equity and earnings per share

2011 Equity Financing

On May 26, 2011, the Company closed a private offering exempt from registration under the Securities Act of 1933 pursuant to Rule 506 of Regulation D promulgated thereunder. In the offering, the Company issued an aggregate of 3,600,000 units. Each unit was sold at $1.50 and was comprised of one share of common stock and one five-year warrant to purchase a share of common stock at an exercise price of $2.25 per share. The warrants became exercisable on November 26, 2011. The Company agreed to use the net proceeds from the sale of the units for general business and working capital purposes and not to use such proceeds for the redemption of any common stock or common stock equivalents.

The investors in the offering (“Selling Stockholders”) received registration rights. The Company agreed to file a registration statement covering the resale of the common stock issued and the common stock underlying the warrants issued to the Selling Stockholders within sixty days after the closing date. If the registration statement was not declared effective by the SEC within the time periods defined within the agreement, then the Company would have made pro rata cash payments to each Selling Stockholder as liquidated damages in an amount equal to 1.0% of the aggregate amount invested by such Selling Stockholder for each 30-day period or pro rata for any portion thereof following the date by which such Registration Statement should have been effective. If at the time of exercise of the warrants there is no effective registration statement covering the resale of the shares underlying the warrant, then the Selling Stockholders have the right at such time to exercise warrants in full or in part on a cashless basis. The Company filed an S-1 registration statement registering the shares on July 25, 2011, which was declared effective on August 5, 2011. In April 2015, the foregoing registration statement was terminated by the Company.

In addition to registration rights, the Selling Stockholders were offered a right of first refusal to participate in future offerings of common stock if the principal purpose of which was to raise capital. This right of first refusal terminated upon the one-year anniversary of the closing date.

Warrants

In connection with the equity offering closed on May 26, 2011, the Company issued warrants to purchase an aggregate of 3,600,000 shares of the Company’s common stock at a per share price of $2.25 (the “$2.25 Warrants”). The Company also has outstanding warrants to purchase 3,125 shares of the Company’s common stock at a per share price of $5.00. The $2.25 Warrants became exercisable in November 2011 and expire in November 2015. On the date of issuance, the warrants were valued at $898,384. Management determined the fair value of the warrants based upon the Black-Scholes option model with a volatility based on the historical closing price of common stock of industry peers and the closing price of the Company’s common stock on the OTCBB on the date of issuance. The volatility and remaining term was 50% and 2.92 years, respectively. The Company does not expect the immediate exercise of these warrants as the exercise price exceeds the average closing market price for the Company’s common stock. Furthermore, no assurances can be made that any of the warrants will ever be exercised for cash or at all.

Stock Options

In 2011, the Company issued options to purchase 87,500 shares of its common stock at $4.80 to its directors. For the three and nine months ended September 30, 2014, there was no stock based compensation.

Stock option activity summary is presented in the table below:

					Weighted-
					average
			Weighted-		Remaining
			average		Contractual
	Number of		Exercise		Term
	Shares		Price		(years)
Outstanding and exercisable December 31, 2012		87,500	$	4.80		4.08
Granted		—		—		—
Cancelled		—		—		—
Exercised		—		—		—
Forfeited		—		—		—
Expired		—		—		—
Outstanding and exercisable at December 31, 2013		87,500		4.80		3.08
Granted		—		—		—
Cancelled		—		—		—
Exercised		—		—		—
Forfeited		—		—		—
Expired		—		—		—
Outstanding and exercisable at September 30, 2014		87,500	$	4.80		2.33

There is no intrinsic value in the outstanding options since the option price is in excess of the market price of the Company’s common stock.

The fair value of the options granted during 2011 was estimated at the date of grant using the Black-Scholes option-pricing model with the following assumptions:

Closing market price of stock on grant date	$	3.11
Risk-free interest rate		2.43	%
Dividend yield		0.00	%
Volatility factor		50	%
Expected life		2.5 years

The Company elected to use the “simplified” method to calculate the estimated life of options granted to employees. The use of the “simplified” method has been extended until such time when the Company has sufficient information to make more refined estimates on the estimated life of its options. The expected stock price volatility was calculated by averaging the historical volatility of the Company’s common stock over a term equal to the expected life of the options.

Issuance of Common Shares to Settle Creditors Payable

The Company entered into settlement agreements with two of the creditors payable arising out of the 2002 bankruptcy. The Company paid the creditors $633,975 in cash and the Company’s largest shareholder, Red Mountain Resources, Inc. (“RMR”), issued approximately 750,000 shares of its common stock to the creditors in settlement of the claims. In return for RMR issuing its shares to the creditors payable, the Company issued RMR 422,650 shares of its common stock.

Conversion of Notes Payable

On February 28, 2013, RMR, the holder of the Green Shoe and Little Bay notes, elected to convert the outstanding notes and accrued interest into common shares. The board of directors of the Company had previously resolved to change the conversion feature from $4.00 per common share to $1.50 per common share. As a result, the Company issued 611,630 common shares to RMR.

7. Related party transactions

The Company and RMR are party to a Technical Services Agreement under which RMR incurs costs on behalf of the Company, primarily related to wells in the Company’s Tom Tom and Tomahawk fields. During the three months ended September 30, 2014, RMR incurred $806,228 on behalf of the Company. During the period ended September 30, 2014, the Company advanced RMR $2,365,000 to use for its general and administrative and operating costs. The net amount of $1,558,772 is shown on the Company’s balance sheet under the caption Accounts Receivable – Related Party.

8. Long term debt

Operating Line of Credit

On February 5, 2013, the Company entered into a Senior First Lien Secured Credit Agreement with RMR, Black Rock Capital, Inc. and RMR Operating, LLC, as borrowers (the “Borrowers”) and Independent Bank, as lender (the “Lender”), providing for an up to $100,000,000 credit facility (the “Credit Facility”). RMR owns approximately 83% of the outstanding common stock of Cross Border, and Black Rock and RMR Operating are wholly owned subsidiaries of RMR. On February 5, 2013, the Company drew $8,900,000 on the line of credit and used those funds to pay off its prior line of credit and associated accrued interest. On February 29, 2013, the Company drew $2,000,000 and on May 24, 2013, the Company drew a further $1,300,000 on the line of credit and used those funds to pay accounts payable related to the drilling program. Effective June 30, 2014, RMR assumed the Company’s obligations with respect to $3,000,000 of the Company’s outstanding borrowings under the Credit Facility in exchange for the satisfaction and discharge of a intercompany payables from RMR to the Company.

The borrowing base under the Credit Facility is determined at the discretion of the Lender based on, among other things, the Lender’s estimated value of the proved reserves attributable to the Borrowers’ oil and natural gas properties that have been mortgaged to the Lender, and is subject to regular redeterminations on September 30 and March 31 of each year, and interim redeterminations described in the Credit Agreement and potentially monthly commitment reductions, in each case which may reduce the amount of the borrowing base. As of September 30, 2014, the borrowers had borrowed a total of $27,800,000. As of September 30, 2014, the Company’s outstanding amount on the line of credit totaled $9,200,000.

On March 11, 2015, Red Mountain Resources, Inc. (the “Red Mountain”) entered into an amendment and waiver (the “Amendment”) to the Senior First Lien Secured Credit Agreement, dated February 5, 2013 (the “Credit Agreement”), with Cross Border Resources, Inc. (“Company”), Black Rock Capital, Inc. (“Black Rock”) and RMR Operating, LLC (“RMR Operating”), as borrowers (the “Borrowers”), and Independent Bank, as lender (“Lender”). Each of the Company, Black Rock and RMR Operating are subsidiaries of Red Mountain. Pursuant to the Amendment, (i) Lender waived any default or right to exercise any remedy as a result of the failure by the Borrowers to be in compliance with the requirements of Section 6.18 of the Credit Agreement with respect to the permitted ratio of consolidated current assets to consolidated current liabilities of Borrowers for the fiscal quarter ended September 30, 2014; and (ii) the borrowing base was decreased from $30 million to $27.8 million, effective as of March 1, 2015, and the commitment amount was decreased to $27.8 million, subject to monthly commitment reductions of $350,000 beginning March 1, 2015.

On April 21, 2015, the Company entered into an amendment (the “Fourth Amendment”) to the Credit Agreement, with the other Borrowers and the Lender. Pursuant to the Fourth Amendment, the borrowing base was decreased from $27.8 million to $12.4 million, effective as of April 21, 2015, and the commitment amount was decreased to $12.4 million. In addition, the monthly commitment reduction amount was set to $0 as of April 1, 2015.

9. Commitments and contingencies

Litigation

The Company, the Company’s former Chief Executive Officer, and the Company’s former Chief Operating Officer are party to a lawsuit with a former employee. On May 4, 2011, Clifton M. (Marty) Bloodworth initially filed a lawsuit in the State District Court of Midland County, Texas, against Doral West Corp. d/b/a Doral Energy Corp. (the predecessor entity of Cross Border) (“Doral Energy”) and Everett Willard Gray II, the Company’s former Chief Executive Officer. Mr. Bloodworth later amended his lawsuit to name Horace Patrick Seale, the Company’s former Chief Operating Officer, as an additional defendant. Mr. Bloodworth generally alleges that Mr. Gray and Mr. Seale, as agents of the Company, made false representations which induced Mr. Bloodworth to enter into an employment contract that was subsequently breached by the Company. The claims that Mr. Bloodworth has alleged are: breach of his employment agreement with Doral Energy, fraud in the inducement and common law fraud, civil conspiracy, breach of fiduciary duty, and violation of the Texas Deceptive Trade Practices Act. Mr. Bloodworth is seeking damages of approximately $280,000. Mr. Gray, Mr. Seale and the Company deny that Mr. Bloodworth’s claims have any merit.

The Company was previously party to an engagement letter, dated February 7, 2012 (the “Engagement Letter”) with KeyBanc Capital Markets Inc. (“KeyBanc”) pursuant to which KeyBanc was to act as exclusive financial advisor to the Company’s board of directors in connection with a possible “Transaction” (as defined in the Engagement Letter). The Engagement Letter was formally terminated by the Company on August 21, 2012. The Engagement Letter provided that KeyBanc would be entitled to a fee upon consummation of a Transaction within a certain period of time following termination of the Engagement Letter. On May 16, 2013, KeyBanc delivered an invoice to the Company representing a fee and out-of-pocket expenses purportedly owed by the Company to KeyBanc as a result of the consummation of a purported Transaction that KeyBanc asserts had been consummated within the required time period. The Company disputed that any Transaction was consummated and that KeyBanc was entitled to any fees or out-of-pocket expenses. The Company filed a complaint seeking (i) a declaration that it was not liable to KeyBanc for any amounts in connection with the Engagement Letter, (ii) attorneys’ fees, and (iii) costs of suit. KeyBanc filed a counterclaim seeking (i) compensatory damages, (ii) interest, (iii) expenses and court costs, and (iv) reasonable and necessary attorneys’ fees. The matter was originally filed in the 44th Judicial District Court for the State of Texas, Dallas County but was subsequently removed to the United States District Court for the Northern District of Texas, Dallas Division. On August 26, 2014, the Company entered into a settlement agreement with KeyBanc, settling a lawsuit between the parties. In connection with the settlement, the Company agreed to pay KeyBanc $900,000 in three equal installments of $300,000 each on or before August 28, 2014, October 31, 2014 and December 31, 2014, and the parties agreed to mutual releases of liability related to the Engagement Letter. The Company paid the first installment and the remaining installments are recorded in accrued expenses on the Company’s Balance Sheet at September 30, 2014.

In addition to the foregoing, in the ordinary course of business, the Company is periodically a party to various litigation matters that it does not believe will have a material adverse effect on its results of operations or financial condition.

Environmental Contingencies

The Company is subject to federal and state laws and regulations relating to the protection of the environment. Environmental risk is inherent in all oil and natural gas operations, and the Company could be subject to environmental cleanup and enforcement actions. The Company manages this environmental risk through appropriate environmental policies and practices to minimize the impact to the Company.

As of September 30, 2014 and December 31, 2013, the Company had approximately $2.1 million in environmental remediation liabilities related to the Company’s operated Tom Tom and Tomahawk fields located in Chaves and Roosevelt counties in New Mexico. In February 2013, the Bureau of Land Management (“BLM”) accepted the Company’s remediation plan for the Tom Tom and Tomahawk fields. The Company is working in conjunction with the BLM to initiate remediation on a site-by-site basis. This is management’s best estimate of the costs of remediation and restoration with respect to these environmental matters, although the ultimate cost could differ materially. Inherent uncertainties exist in these estimates due to unknown conditions, changing governmental regulation, and legal standards regarding liability, and emerging remediation technologies for handling site remediation and restoration. The Company expects to incur the remaining costs during the next fiscal year.

10. Price risk management activities

ASC 815-25 (formerly SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities”) requires that all derivative instruments be recorded on the balance sheet at their fair value. Changes in the fair value of each derivative are recorded each period in current earnings or other comprehensive income, depending on whether the derivative is designated as part of a hedge transaction and, if it is, the type of hedge transaction. When choosing to designate a derivative as a hedge, management formally documents the hedging relationship and its risk-management objective and strategy for undertaking the hedge, the hedging instrument, the item, the nature of the risk being hedged, how the hedging instrument’s effectiveness in offsetting the hedged risk will be assessed, and a description of the method of measuring effectiveness. This process includes linking all derivatives that are designated as cash-flow hedges to specific cash flows associated with assets and liabilities on the balance sheet or to specific forecasted transactions. Based on the above, management has determined the swaps noted below do not qualify for hedge accounting treatment.

At September 30, 2014, the Company had a net derivative asset of $12,028, as compared to a net derivative liability of $38,109 at December 31, 2013. The change in net derivative asset/liability is recorded as non-cash mark-to-market income or loss. Mark-to-market income of $50,138 was recorded in the nine months ended September 30, 2014 as compared to mark-to-market income of $283,831 during the twelve months ended December 31, 2013. Net realized hedge settlement loss for the nine months ended September 30, 2014 was $95,341 as compared to net realized hedge settlement loss of $14,062 for the twelve months ended December 31, 2013. The combination of these two components of derivative expense/income is reflected in “Other Income (Expense)” on the Statements of Operations as “Gain (loss) on derivatives.”

As of September 30, 2014, the Company had crude oil swaps in place relating to a total of 2,000 Bbls per month, as follows:

											Fair Value of Outstanding Derivative Contracts (1) as of
Transaction							Price Per		Volumes Per		September 30,		December 31,
Date	Type (2)		Beginning		Ending		Unit		Month		2014		2013
November 2011		Swap		12/01/2011		11/30/2014	$	93.50		2,000		12,028		(62,730	)
February 2012		Swap		03/01/2012		02/28/2014	$	106.50		1,000		—		24,621
											$	12,028	$	(38,109	)

(1) The fair value of the Company’s outstanding transactions is presented on the balance sheet by counterparty. Currently all of our derivatives are with the same counterparty. The balance is shown as current or long-term based on our estimate of the amounts that will be due in the relevant time periods at currently predicted price levels. Amounts in parentheses indicate liabilities.

(2) These crude oil hedges were entered into on a per barrel delivered price basis, using the NYMEX - West Texas Intermediate Index, with settlement for each calendar month occurring following the expiration date, as determined by the contracts.

11. Fair Value Measurements

Fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. These two types of inputs are further prioritized into the following fair value input hierarchy:

Level 1 –

quoted prices for identical assets or liabilities in active markets.

Level 2 –

quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability (e.g. interest rates) and inputs derived principally from or corroborated by observable market data by correlation or other means.

Level 3 –

unobservable inputs for the asset or liability.

The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety.

The following tables summarize the valuation of the Company’s financial assets and liabilities at September 30, 2014 and December 31, 2013:

	Fair Value Measurements at Reporting Date Using
	Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant or Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)			Fair Value at September 30, 2014
Assets:
Commodities derivatives	$	—	$	12,028	$	—		$	12,028
Total	$	—	$	12,028	$	—		$	12,028

Liabilities
Environmental liability	$	—	$	—	$	(2,057,175	)	$	(2,057,175	)
Asset retirement obligations (non-recurring)	$	—	$	—	$	(1,576,521	)	$	(1,576,521	)
Total	$	—	$	—	$	(3,633,696	)	$	(3,633,696	)

	Fair Value Measurements at Reporting Date Using
	Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant or Other Observable Inputs (Level 2)			Significant Unobservable Input (Level 3)			Fair Value at December 31, 2013
Liabilities:
Environmental liability	$	—	$	—		$	(2,086,239	)	$	(2,086,239	)
Commodities derivatives		—		(38,109	)					(38,109	)
Asset retirement obligations (non-recurring)		—		—			(3,514,898	)		(3,514,898	)
Total	$	—	$	(38,109	)	$	(5,601,137	)	$	(5,639,246	)

12. Subsequent Events

The Company evaluated subsequent events through the date the financial statements were issued and filed with the U.S. Securities and Exchange Commission.

On April 21, 2015, the Company entered into a purchase and sale agreement (the “PSA”) with RMR Operating, LLC (“RMR Operating”), Black Rock Capital, Inc. (“Black Rock”), RMR KS Holdings, LLC (“RMR KS”) and Black Shale Minerals, LLC (“Buyer”). Each of the Company, RMR Operating, Black Rock and RMR KS is an operating subsidiary (together, the “Operating Subsidiaries”) of Red Mountain Resources, Inc. (“RMR,” and together with the Operating Subsidiaries, the “Companies”).

Pursuant to the PSA the Operating Subsidiaries sold, assigned, transferred and conveyed to Buyer, effective as of April 1, 2015, fifty percent (50%) of their right, title, and interest in and to certain oil and natural gas assets and properties (the “Assets”), including their oil and natural gas leasehold interests, wells, contracts, and oil and natural gas produced after April 1, 2015 (the “Sale”). The aggregate purchase price for the Assets under the PSA was $25.0 million, subject to certain adjustments, including post-closing adjustments for any title or environmental benefits or title or environmental defects resulting from Buyer’s title and environmental reviews.

As of September 30, 2014, the carrying values of the Company’s ownership in half of its interest in its oil and gas properties, mineral interests, and leaseholds were included in assets and liabilities held for sale in the accompanying balance sheet and were comprised of the following (the Company had no assets held for sale as of September 30, 2013):

	September 30,
	2014
Composition of assets included in assets held for sale:
Oil and Gas Properties, Net	$	14,951,977
Composition of liabilities included in liabilities held for sale:
Asset Retirement Obligations	$	1,576,522

Non-current assets and liabilities held for sale are presented in current assets and current liabilities, respectively, within the balance sheet. Assets held for sale are not depreciated, depleted or amortized and they are measured at the lower of the fair value less costs to sell and their carrying amount. Comparative period balance sheets are not restated.

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Our Company

We are an oil and gas exploration and development company. We currently own over 865,893 gross (approximately 146,922 net) mineral and lease acres in New Mexico. Approximately 12,825 of these net acres exist within the Permian Basin. A significant majority of our acreage consists of either owned mineral rights or leases held by production. The majority of our acreage interests consists of non-operated working interests except for certain core San Andres properties which we operate.

Current development of our acreage is focused on our prospective Bone Spring acreage located in the heart of the 1st and 2nd Bone Spring play. This play encompasses approximately 4,390 square miles across both New Mexico and Texas. We currently own varying, non-operated working interests in both Eddy and Lea Counties, New Mexico, along with our working interest partners that include Cimarex, Apache, Oxy Permian, Occidental, Oxy USA and, Mewbourne; all having significant footprints within this play, and are adding to those footprints through lease and corporate acquisitions.

History

We were originally formed on October 25, 2005 under the name “Language Enterprises Corp.” We subsequently changed our name to Doral Energy Corp. On July 29, 2008, we acquired a working interest in 66 producing oil fields and approximately 186 wells (the “Eddy County Properties”) in and around Eddy County, New Mexico. As a result of our acquisition of the Eddy County Properties, we changed our business focus to the acquisition, exploration, operation and development of oil and gas projects, and we ceased being a “shell company.” On August 4, 2008, we filed our Form 8-K that included the information that would be required if we were filing a general form for registration of securities on Form 10 as a smaller reporting company.

Effective January 3, 2011, we completed the acquisition of Pure Energy Group, Inc. as contemplated pursuant to the Pure Merger Agreement among our company, Doral Sub, Pure L.P. and Pure Sub, a wholly owned subsidiary of Pure L.P. Pursuant to the provisions of the Pure Merger Agreement, all of Pure L.P.’s oil and gas assets and liabilities were transferred to Pure Sub. Pure Sub was then merged with and into Doral Sub, with Doral Sub continuing as the surviving corporation. Upon completion of the Pure Merger, the outstanding shares of Pure Sub were converted into an aggregate of 9,981,536 shares of our common stock. Since the Pure Merger, Pure L.P. has distributed all of its shares of our common stock to the partners of Pure L.P. so that Pure L.P. is no longer a shareholder of our company.

Effective January 4, 2011, following closing of the Pure Merger, Doral Sub was merged with and into our company, with our company continuing as the surviving corporation. Upon completing the merger of Doral Sub with and into our company, we changed our name to “Cross Border Resources, Inc.”

On January 28, 2013, Red Mountain Resources, Inc. closed the acquisition of 5,091,210 shares of our common, bringing its total ownership to approximately 78% of the outstanding common stock of the company. Prior to the acquisition, Red Mountain Resources, Inc. owned 47% of our outstanding common stock. As of the date of this report, Red Mountain Resources, Inc. owns approximately 83% of our outstanding common stock. As a result of that transaction, our results are consolidated in Red Mountain Resources, Inc.’s financial statements.

On April 21, 2015, we entered into a purchase and sale agreement (the "PSA") with RMR Operating, LLC ("RMR Operating"), Black Rock Capital, Inc. ("Black Rock"), RMR KS Holdings, LLC ("RMR KS") and Black Shale Minerals, LLC ("Buyer"). Each of us, RMR Operating, Black Rock and RMR KS is an operating subsidiary (together, the "Operating Subsidiaries") of Red Mountain Resources, Inc. ("RMR," and together with the Operating Subsidiaries, the "Companies").

Pursuant to the PSA the Operating Subsidiaries sold, assigned, transferred and conveyed to Buyer, effective as of April 1, 2015, fifty percent (50%) of their right, title, and interest in and to certain oil and natural gas assets and properties (the "Assets"), including their oil and natural gas leasehold interests, wells, contracts, and oil and natural gas produced after April 1, 2015 (the "Sale"). The aggregate purchase price for the Assets under the PSA was $25.0 million, subject to certain adjustments, including post-closing adjustments for any title or environmental benefits or title or environmental defects resulting from Buyer's title and environmental reviews.

Third Quarter 2014 Operational Update

During the three months ended September 30, 2014, Cross Border completed 2 wells (0.2 net). Both of these wells were in the Turkey Track area. The first, Zircon 2 B1EH State 2H, was completed in July 2014 in the 1st Bone Spring sand. The well achieved a 10-day average production rate of 549 BOE/d (81% oil). We own 12.5% working interest and 10.0% net revenue interest in the well. The second well, Bradley 31 B2DA Fed Com 1H, was completed in September 2014 in the 2nd Bone Spring sand. This well achieved a 10-day average production rate of 790 BOE/d (88% oil). We own 7.0% working interest 6.1% net revenue interest in the well. As of April 1, 2015, the aforementioned working interest and net revenue interest were proportionately reduced by 50% pursuant to the terms of the Sale.

Planned Operations

In the remainder of 2014, we plan to spend approximately $2.0 million to drill and complete wells, re-enter and complete wells, or improve infrastructure. We plan to spend the majority of this capital will be focused on non-operated areas, where we will drill 5 wells (0.4 net) to various objectives, including 2nd Bone Spring, 3rd Bone Spring, and Yeso reservoirs.. We expect to finance these activities with cash flow generated from operations and availability under our line of credit with Independent Bank.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations is based upon our financial statements, which have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”). The preparation of these financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenue and expenses, and related disclosures. Our significant accounting policies are described in “Note 3—Summary of Significant Accounting Policies” to our financial statements included in this Annual Report on Form 10-K. We have identified below policies that are of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by management. These estimates are based on historical experience, information received from third parties, and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions.

We believe the following critical accounting policies affect the significant judgments and estimates used in the preparation of our financial statements.

Oil and Gas Properties

We follow the successful efforts method of accounting for our oil and natural gas producing activities. Costs to acquire mineral interests in oil and natural gas properties and to drill and equip development wells and related asset retirement costs are capitalized. Costs to drill exploratory wells are capitalized pending determination of whether the wells have proved reserves. If we determine that the wells do not have proved reserves, the costs are charged to expense. There were no exploratory wells capitalized pending determination of whether the wells have proved reserves at September 30, 2014 or December 31, 2013. Geological and geophysical costs, including seismic studies and costs of carrying and retaining unproved properties, are charged to expense as incurred. We capitalize interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use. Through September 30, 2014, we had capitalized no interest costs because our exploration and development projects generally lasted less than six months. Costs incurred to maintain wells and related equipment are charged to expense as incurred.

On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depreciation, depletion and amortization are eliminated from the property accounts, and the resultant gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depreciation, depletion and amortization, with a resulting gain or loss recognized in income.

Capitalized amounts attributable to proved oil and natural gas properties are depleted by the unit-of-production method over proved reserves using the unit conversion ratio of six Mcf of natural gas to one Boe. The ratio of six Mcf of natural gas to one Boe is based on energy equivalency, rather than price equivalency. Given current price differentials, the price for a Boe for natural gas differs significantly from the price for a barrel of oil.

It is common for operators of oil and natural gas properties to request that joint interest owners pay for large expenditures, typically for drilling new wells, in advance of the work commencing. This right to call for cash advances is typically found in the operating agreement that joint interest owners in a property adopt. We record these advance payments in prepaid and other current assets in its property account and release this account when the actual expenditure is later billed to it by the operator.

Impairment of Long-Lived Assets

We evaluate our long-lived assets for potential impairment in their carrying values whenever events or changes in circumstances indicate such impairment may have occurred. Oil and natural gas properties are evaluated for potential impairment by field. Other properties are evaluated for impairment on a specific asset basis or in groups of similar assets, as applicable. An impairment on proved properties is recognized when the estimated undiscounted future net cash flows of an asset are less than its carrying value. If an impairment occurs, the carrying value of the impaired asset is reduced to its estimated fair value, which is generally estimated using a discounted cash flow approach. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized.

Unproved oil and natural gas properties do not have producing properties. As reserves are proved through the successful completion of exploratory wells, the cost is transferred to proved properties. The cost of the remaining unproved basis is periodically evaluated by management to assess whether the value of a property has diminished. To do this assessment, management considers estimated potential reserves and future net revenues from an independent expert, our history in exploring the area, our future drilling plans per our capital drilling program prepared by our reservoir engineers and operations management and other factors associated with the area. Impairment is taken on the unproved property cost if it is determined that the costs are not likely to be recoverable. The valuation is subjective and requires management to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual results.

Recent Accounting Pronouncements

In April 2014, the FASB issued Accounting Standards Update (“ASU”) 2014-08, Reporting Discontinued Operations and Disclosures of Components of an Entity(“ASU 2014-08”). ASU 2014-08 revises the definition of discontinued operations by limiting discontinued operations reporting to disposals of components of an entity that represent strategic shifts that have (or will have) a major effect on an entity’s operations and financial results, removing the lack of continuing involvement criteria and requiring discontinued operations reporting for the disposal of an equity method investment that meets the definition of discontinued operations. The update also requires expanded disclosures for discontinued operations, including disclosure of pretax profit or loss of an individually significant component of an entity that does not qualify for discontinued operations reporting. The update is effective prospectively to all periods beginning after December 15, 2014. Currently, we do not expect the adoption of ASU 2014-08 to have a material impact on our financial statements or results of operations.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 amends the existing accounting standards for revenue recognition and is based on the principle that revenue should be recognized to depict the transfer of goods or services to a customer at an amount that reflects the consideration a company expects to receive in exchange for those goods or services. The update is effective for periods beginning after December 15, 2016. We are currently assessing the potential impact of ASU 2014-09 on our financial statements and results of operations.

In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“ASU 2014-15”), an amendment to FASB Accounting Standards Codification (“ASC”) Topic 205, Presentation of Financial Statements. This update provides guidance on management’s responsibility in evaluating whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. This ASU 2014-15 is effective for annual periods ending after December 15, 2016, and for annual and interim periods thereafter. Early adoption is permitted. We do not expect the adoption of ASU 2014-15 to have a material impact on our financial statements or results of operations. If events occur in future periods that could affect our ability to continue as a going concern, we will provide the disclosures required by ASU 2014-15.

We have reviewed recently issued, but not yet adopted, accounting standards as noted in Footnote 3 of notes to the financial statements in order to determine their effects, if any, on our results of operations, financial position and cash flows. Based on that review, we believe that none of these recent pronouncements will have a significant effect on our current or future earnings or operations.

Results of Operations

Three Months Ended September 30, 2014 Compared to Three Months Ended September 30, 2013

The following table sets forth summary information regarding our oil and natural gas sales, net production sold, average sales prices and production costs and expenses for the three months ended September 30, 2014 and 2013.

	Three Months Ended September 30,
	2014		2013
(In thousands except per Boe amounts)
Revenue
Total Sales	$	2,962	$	3,430

Net Production sold
Oil (Bbl)		32,029		31,329
Natural gas (Mcf)		59,935		85,428
Natural gas liquids (Bbl)		4,006		3,269
Total (Boe)		46,024		48,863

Average sales prices
Oil ($/Bbl)	$	82.14	$	96.05
Natural gas ($/Mcf)		3.49		3.75
Natural gas liquids ($/Bbl)		30.45		25.47
Total average price ($/Boe)	$	64.35	$	69.89

Costs and expenses (per Boe)
Operating costs and marketing	$	13.20	$	11.25
Production taxes		5.42		7.96
Depreciation, depletion, amortization, and impairment		150.87		22.16
Accretion of discount on asset retirement obligation		0.38		0.78
General and administrative expense		4.43		5.15

Three months Revenues and Sales Volumes

Oil and Natural Gas Sales Volumes. During the three months ended September 30, 2014, we had total sales volumes of 46,024 Boe, compared to total sales volumes of 48,863 Boe during the three months ended September 30, 2013. This decrease is primarily attributable to the natural decline in production partially offset by new wells.

Oil and Natural Gas Sales. During the three months ended September 30, 2014, we had oil and natural gas sales of $3.0 million, as compared to $3.4 million during the three months ended September 30, 2013.

Costs and Expenses

Operating Costs. During the three months ended September 30, 2014, we incurred operating costs of $0.6 million, as compared to $0.5 million during the three months ended September 30, 2013.

Production Taxes. Production taxes were $0.2 million for the three months ended September 30, 2014, as compared to $0.4 million for the three months ended September 30, 2013.

Depreciation, Depletion, Amortization and Impairment. For the three months ended September 30, 2014, depreciation, depletion, amortization, and impairment was $6.9 million, as compared to $1.1 million for the quarter ended September 30, 2013. The lower depletion is primarily a result of lower capitalized asset retirement costs as a result of a decrease to the asset retirement obligation and higher reserves in certain of our fields.

General and Administrative Expense. General and administrative expense was $0.2 million for the three months ended September 30, 2014, as compared to $0.3 million for the three months ended September 30, 2013.

Other Expense / Income. Other expense was $0.9 million for the three months ended September 30, 2014, as compared to other expense of approximately $0.5 for the three months ended September 30, 2013. The difference is primarily attributable to lower interest expense for the three months ended September 30, 2014 and an increase in gain on derivatives of approximately $0.4 million, offset by a $0.9 million loss on settlement of litigation.

Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2013

The following table sets forth summary information regarding our oil and natural gas sales, net production sold, average sales prices and production costs and expenses for the nine months ended September 30, 2014 and 2013.

	Nine Months Ended September 30,
	2014		2013

Revenue
Total Sales	$	10,149	$	10,224

Net Production sold
Oil (Bbl)		99,406		93,252
Natural gas (Mcf)		203,679		219,046
Natural gas liquids (Bbl)		11,382		6,276
Total (Boe)		144,734		136,036

Average sales prices
Oil ($/Bbl)	$	87.90	$	94.99
Natural gas ($/Mcf)		5.14		4.77
Natural gas liquids ($/Bbl)		32.05		27.60
Total average price ($/Boe)	$	70.12	$	74.07

Costs and expenses (per Boe)
Operating costs and marketing	$	11.25	$	14.20
Production taxes		5.70		5.76
Depreciation, depletion, amortization, and impairment		60.97		28.50
Accretion of discount on asset retirement obligation		1.17		0.81
General and administrative expense		4.40		6.23

Nine months Revenues and Sales Volumes

Oil and Natural Gas Sales Volumes. During the nine months ended September 30, 2014, we had total sales volumes of 144,734 Boe, compared to total sales volumes of 136,036 Boe during the nine months ended September 30, 2013. This increase is primarily attributable to production from new wells, partially offset by natural decline in production.

Oil and Natural Gas Sales. During the nine months ended September 30, 2014, we had oil and natural gas sales of $10.1 million, as compared to $10.2 million during the nine months ended September 30, 2013.

Costs and Expenses

Operating Costs. During the nine months ended September 30, 2014, we incurred operating costs of $1.5 million, as compared to $1.9 million during the nine months ended September 30, 2013, primarily as a result of lower workover expenditures.

Production Taxes. Production taxes were $0.8 million for the nine months ended September 30, 2014, as compared to $0.8 million for the nine months ended September 30, 2013.

Depreciation, Depletion, Amortization and Impairment. For the nine months ended September 30, 2014, depreciation, depletion, amortization, and impairment was $8.8 million, as compared to $3.9 million for the nine months ended September 30, 2013. The increase is primarily attributable to the $6.5 million impairment we recognized during the nine months ended September 30, 2014.

General and Administrative Expense. General and administrative expense was $0.6 million for the nine months ended September 30, 2014, as compared to $0.8 million for the nine months ended September 30, 2013. The decrease is primarily attributable to lower professional fees.

Other Expense / Income. Other expense was $1.3 million for the nine months ended September 30, 2014, as compared to other income of $0.1 million for the nine months ended September 30, 2013. The increase in other expense is primarily attributable to the loss on settlement of litigation which was not incurred during the nine months ended September 30, 2013, a decrease in loss of derivatives of approximately $0.3 million, and a decrease in interest expense of approximately $0.1 million. During the nine months ended September 30, 2013 there was a gain on settlement of debt of approximately $0.9 million while there was no corresponding gain during the nine months ended September 30, 2014.

Liquidity and Capital Resources

General

Our primary sources of liquidity are cash flow from operations. Our ability to fund planned capital expenditures and to make acquisitions depends upon our future operating performance and availability of equity and debt financing, which is affected by prevailing economic conditions in our industry and financial, business and other factors, some of which are beyond our control. Our cash flow from operations is mainly influenced by the prices we receive for our oil and natural gas production and the quantity of oil and natural gas we produce. Prices for oil and natural gas are beyond our control and are affected by national and international economic and political conditions, national and global supply and demand for hydrocarbons, seasonal weather influences and other factors beyond our control. The price we receive for oil has fallen significantly since June 2014 and may remain at depressed levels for the foreseeable future.

Capital Expenditures

Most of our capital expenditures are for the exploration, development, and production of oil and natural gas reserves. For the nine months ended September 30, 2014, we had capital expenditures of approximately $3.2 million for the development of oil and natural gas properties. We anticipate capital expenditures of approximately $2.0 million for the remainder of 2014. See “Planned Operations” for more information about our planned capital expenditures.

Liquidity

At September 30 2014, we had approximately $0.4 million in cash and cash equivalents and $9.2 million outstanding under our line of credit with Independent Bank. At September 30, 2014, we had working capital of approximately $3.8 million (including assets held for sale of $14.9 million) compared to a working capital deficit of approximately $0.4 million at September 30, 2013.

On February 5, 2013, we entered into a Senior First Lien Secured Credit Agreement with Independent Bank. Our initial draw on the line of credit was $8.9 million which was primarily used to pay off the Texas Capital Bank line of credit principal and accrued interest. On February 28, 2013, we drew $2,000,000 and on May 24, 2013, we drew a further $1,300,000 on the line of credit and used those funds to pay accounts payable related to the drilling program.

On March 11, 2015, we entered into an amendment and waiver (the “Third Amendment”) to the Senior First Lien Secured Credit Agreement, dated February 5, 2013, as amended (the “Credit Agreement”), with RMR, Black Rock and RMR Operating (together with the Company, the “Borrowers”) and Independent Bank (“Lender”). Pursuant to the Third Amendment, (i) the Lender waived any default or right to exercise any remedy as a result of the failure by the Borrowers to be in compliance with the requirements of Section 6.18 of the Credit Agreement with respect to the permitted ratio of consolidated current assets to consolidated current liabilities of Borrowers for the fiscal quarter ended September 30, 2014; and (ii) the borrowing base was decreased from $30 million to $27.8 million, effective as of March 1, 2015, and the commitment amount was decreased to $27.8 million, subject to monthly commitment reductions of $350,000 beginning March 1, 2015.

On April 21, 2015, we entered into an amendment (the “Fourth Amendment”) to the Credit Agreement, with the other Borrowers and the Lender. Pursuant to the Fourth Amendment, the borrowing base was decreased from approximately $27.8 million to $12.4 million, effective as of April 21, 2015, and the commitment amount was decreased to $12.4 million. In addition, the monthly commitment reduction amount was set to $0 as of April 1, 2015.

Cash Flows

Net cash provided by operating activities was approximately $5.9 million for the nine months ended September 30, 2014, compared to net cash provided by operating activities of $5.9 million for the nine months ended September 30, 2013.

Net cash used in investing activities decreased to approximately $3.1 million for the nine months ended September 30, 2014 from $8.0 million for the nine months ended September 30, 2013 due to fewer wells being drilled in the period ended September 30, 2014 as compared to the period ended September 30, 2013.

During the nine months ended September 30, 2014, net cash used in financing was approximately $3.0 million compared to net cash provided by financing of $2.8 million for the nine months ended September 30, 2013.

Indebtedness

Line of Credit

On February 5, 2013, the Company entered into a Senior First Lien Secured Credit Agreement with Red Mountain Resources, Inc., Black Rock Capital, Inc. and RMR Operating, LLC and Independent Bank. Red Mountain owns approximately 83% of the outstanding common stock of Cross Border and Black Rock and RMR Operating are wholly owned subsidiaries of Red Mountain. On February 5, 2013, the Company drew $8,900,000 on the line of credit and used a portion of that draw to fully pay off the Texas Capital Bank line of credit. On February 28, 2013, the Company drew $2,000,000 and on May 24, 2013, the Company drew a further $1,300,000 on the line of credit and used those funds to pay outstanding accounts payable related to our drilling program.

On March 11, 2015, we entered into an amendment and waiver (the “Third Amendment”) to the Senior First Lien Secured Credit Agreement, dated February 5, 2013, as amended (the “Credit Agreement”), with RMR, Black Rock and RMR Operating (together with the Company, the “Borrowers”) and Independent Bank (“Lender”). Pursuant to the Third Amendment, (i) the Lender waived any default or right to exercise any remedy as a result of the failure by the Borrowers to be in compliance with the requirements of Section 6.18 of the Credit Agreement with respect to the permitted ratio of current assets to current liabilities of Borrowers for the fiscal quarter ended September 30, 2014; and (ii) the borrowing base was decreased from $30 million to $27.8 million, effective as of March 1, 2015, and the commitment amount was decreased to $27.8 million, subject to monthly commitment reductions of $350,000 beginning March 1, 2015.

On April 21, 2015, we entered into an amendment (the “Fourth Amendment”) to the Credit Agreement, with the other Borrowers and the Lender. Pursuant to the Fourth Amendment, the borrowing base was decreased from $27.8 million to $12.4 million, effective as of April 21, 2015, and the commitment amount was decreased to $12.4 million. In addition, the monthly commitment reduction amount was set to $0 as of April 1, 2015.

As of September 30, 2014, our indebtedness under the Credit Agreement was $9.2 million.

Off-Balance Sheet Arrangements

As of September 30, 2014, we did not have any off-balance sheet arrangements as defined by Regulation S-K.

Forward-Looking Statements

This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Statements that are not historical facts, including statements about our beliefs and expectations, are forward-looking statements. Forward-looking statements include statements preceded by, followed by or that include the words “may,” “could,” “would,” “should,” believe,” “expect,” anticipate,” “plan,” “estimate,” “target,” “project,” or “intend” or similar expressions and the negative of such words and expressions, although not all forward-looking statements contain such words or expressions.

Forward-looking statements are only predictions and are not guarantees of performance. These statements generally relate to our plans, objectives and expectations for future operations and are based on management’s current beliefs and assumptions, which in turn are based on its experience and its perception of historical trends, current conditions and expected future developments as well as other factors it believes are appropriate under the circumstances. Although we believe that the plans, objectives and expectations reflected in or suggested by the forward-looking statements are reasonable, there can be no assurance that actual results will not differ materially from those expressed or implied in such forward-looking statements. Forward-looking statements also involve risks and uncertainties. Many of these risks and uncertainties are beyond our ability to control or predict and could cause results to differ materially from the results discussed in such forward-looking statements. Such risks and uncertainties include, but are not limited to, the following:

our ability to raise additional capital to fund future capital expenditures;

our ability to comply with debt covenants;

our ability to generate sufficient cash flow from operations, borrowings or other sources to enable us to fully develop and produce our oil and natural gas properties;

declines or volatility in the prices we receive for our oil and natural gas;

general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business;

risks associated with drilling, including completion risks, cost overruns and the drilling of non-economic wells or dry holes;

uncertainties associated with estimates of proved oil and natural gas reserves;

the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs;

risks and liabilities associated with acquired companies and properties;

risks related to integration of acquired companies and properties;

potential defects in title to our properties;

cost and availability of drilling rigs, equipment, supplies, personnel and oilfield services;

geological concentration of our reserves;

environmental or other governmental regulations, including legislation of hydraulic fracture stimulation;

our ability to secure firm transportation for oil and natural gas we produce and to sell the oil and natural gas at market prices;

exploration and development risks;

management’s ability to execute our plans to meet our goals;

our ability to retain key members of our management team;

weather conditions;

actions or inactions of third-party operators of our properties;

costs and liabilities associated with environmental, health and safety laws;

our ability to find and retain highly skilled personnel;

operating hazards attendant to the oil and natural gas business;

competition in the oil and natural gas industry; and

the other factors discussed under Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2013.

Forward-looking statements speak only as of the date hereof. All such forward-looking statements and any subsequent written and oral forward-looking statements attributable to us or any person acting on our behalf are expressly qualified in their entirety by the cautionary statements contained or referred to in this section and any other cautionary statements that may accompany such forward-looking statements. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements.

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

On February 5, 2013, we entered into the Credit Facility, which exposes us to interest rate risk associated with interest rate fluctuations on outstanding borrowings. At September 30, 2014, we had $9.2 million in outstanding borrowings under the Credit Facility. We incur interest on borrowings under the Credit Facility at a rate per annum equal to the greater of (x) the U.S. prime rate as published in The Wall Street Journal’s “Money Rates” table in effect from time to time and (y) 4.0% (4.0 % at September 30, 2014). A hypothetical 10% change in the interest rates we pay on our borrowings under the Credit Facility as of September 30, 2014 would result in an increase or decrease in our interest costs of approximately $32,800 per year.

Item 4.

Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives.

Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we evaluated the effectiveness of our disclosure controls and procedures as of September 30, 2014. Based on that evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective at the reasonable assurance level.

Changes in Internal Control Over Financial Reporting

During the quarter ended September 30, 2014, we engaged an accounting firm with significant public company internal control experience to identify improvements to each of our main business and accounting processes that affect the preparation of our financial statements. The accounting firm and management reviewed each business and accounting process and designed and implemented preventive and detective internal controls. We tested the new internal controls and deem them to be effective as of September 30, 2014.

PART II. OTHER INFORMATION

Item 1.

Legal Proceedings

Please see Note 9 to our unaudited notes to financial statements appearing elsewhere in this Quarterly Report on Form 10-Q.

Item 1A.

Risk Factors

There have been no material changes to the risk factors discussed in our Annual Report on Form 10-K for the year ended December 31, 2013.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3.

Defaults Upon Senior Securities

None.

Item 4.

Mine Safety Disclosures

Not applicable.

Item 5.

Other Information

None.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Dated: May 15, 2015

	By:	/s/ Earl M. Sebring
		Earl M. Sebring
		Interim President

	By:	/s/ Kenneth S. Lamb
		Kenneth S. Lamb
		Chief Accounting Officer, Secretary, and Treasurer

EXHIBIT INDEX

Exhibit No.	Name of Exhibit
31.1	Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. (*)
31.2	Certification of Principal Accounting Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. (*)
32.1	Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (*)
32.2	Certification of Principal Accounting Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (*)
101.INS**	XBRL Instance Document
101.SCH**	XBRL Taxonomy Extension Schema Document
101.CAL**	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF**	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB**	XBRL Taxonomy Extension Label Linkbase Document
101.PRE**	XBRL Taxonomy Extension Presentation Linkbase Document

Filed herewith.

Furnished herewith.